Miscible displacement is a form of enhanced oil recovery in which a fluid which is partially miscible with oil is injected into the oil reservoir. Fluids used for this purpose may be gaseous at ambient temperature and pressure but volatile hydrocarbons and supercritical gas have also been used. Examples of fluids which have been used as drive fluids include methane, liquefied petroleum gas such as propane, and carbon dioxide (which may or may not be in a supercritical state at reservoir temperature and pressure). The fluids are termed ‘miscible’ because they can dissolve in the oil but they are usually not miscible with oil in all proportions. When the miscible drive fluid is injected into a reservoir, it initially dissolves in the oil leading to a diluted oil phase with reduced viscosity. Dissolution of the drive fluid can progress until the oil becomes saturated with the fluid. At the same time some constituents of the oil, generally its more volatile constituents, can dissolve in the drive fluid until the fluid becomes saturated with these. The eventual result, if equilibrium is reached, is two-phase mixture of                (i) oil that has become saturated with dissolved drive fluid and        (ii) drive fluid saturated with oil constituents.        
During such a miscible displacement operation, drive fluid is injected into the formation through one or more injection wells and moves through the reservoir towards one or more production wells. The region where injected fluid meets undiluted original oil is a ‘flood front’ which is typically less than one meter thick. Within this flood front the drive fluid dissolves in the oil until the oil becomes saturated. Behind the flood front there is a free gas phase together with residual oil which is saturated with drive fluid and somewhat depleted of the more volatile constituents of the original oil. This residual oil will be moving more slowly than the drive fluid and flood front. Indeed the residual oil may not be moving within the reservoir at all.
When planning the extraction of oil from a reservoir (whether, or not an enhanced recovery technique is contemplated) it is normal practice to determine the properties of the reservoir—including its pressure and temperature and the composition of the oil in it—and then seek to predict what changes will take place during the course of the recovery operation, with a view to achieving maximum economic recovery of oil. An extraction plan is likely to involve a number of design choices, including the composition of the drive fluid. Capital investment in an enhanced oil recovery operation may be very substantial—high cost of surface processing facilities, for instance. Consequently it may be desirable to monitor progress and changes within the reservoir, to check that the operation is proceeding as predicted, and take remedial action if required—such as by modifying one or more of the original design choices. Possibilities would include changes to the drive fluid composition and/or changes to the relative rates of injection of drive fluid through each of a plurality of injection wells. One parameter of considerable economic importance is the composition of the residual oil which is not recovered.
Techniques for monitoring during miscible displacement include the use of observation wells located intermediately between production wells and injection wells for putting the drive fluid into the reservoir. Nuclear magnetic resonance (NMR) has been used in well logging for a number of years. There are a number of published techniques for obtaining and interpreting NMR data but so-called two dimensional NMR has become well established. A method for obtaining such data is described in U.S. Pat. No. 6,570,382 and a wireline tool for NMR logging is described in U.S. Pat. No. 6,140,818. Both of these documents are incorporated herein by reference. An NMR logging tool which is currently in use is the Schlumberger MR scanner.
Two-dimensional NMR measurements provide a map of diffusion coefficients against spin-spin relaxation time, usually referred to as T2 relaxation time. The coordinates for each point on the map are values of diffusion coefficient and T2 relaxation time and the map shows the concentration of molecules (or proportion of the composition) displaying that combination of the diffusion coefficient and T2 relaxation time. The information given by such a map can be projected as a graph of concentration plotted against relaxation time and also as a graph of concentration plotted against diffusion coefficient. The latter plot, i.e. of concentration against diffusion coefficient, is referred to as a diffusivity distribution. The technique of obtaining such a map has been described in U.S. Pat. No. 6,570,382 in which FIG. 7 shows a map and the two projections.
It has been shown that diffusion coefficients and T2 relaxation times of mixtures of alkanes follow simple scaling laws based on the chain length of the constituents and the mean chain length of the mixture. These scaling laws can be used to calculate chain lengths in a mixture from the distribution of the diffusion coefficients and also to calculate the viscosity of a mixture. Compositions calculated from NMR data are in good agreement with compositions determined by laboratory analysis. See US published application 2004/0253743,
also Freed, Burcaw and Song: “Scaling Laws for Diffusion Coefficients in Mixtures of Alkanes” Physical Review Letters Vol 94, 067602 (2005), Freed: “The dependence on chain length of NMR relaxation times in mixtures of alkanes, J. Chem. Phys. Vol 126, 174502 (2007), and Hürlimann, Freed, Zielinski, Song, Leu, Straley, Cao Minh, and Boyd: “Hydrocarbon composition from NMR diffusion and relaxation data” SPWLA 49th Annual Logging Symposium, May 2008, Paper U. These documents are incorporated herein by reference.
Thus it is possible to infer hydrocarbon fluid composition and viscosity from NMR determinations of diffusion coefficients and T2 relaxation times obtained by NMR logging.
Tools for predicting changes during the course of extraction from a reservoir include a number of proprietary computer programs. For example PVTPro available from Schlumberger is an equation-of-state based program able to predict fluid properties and phase behaviour of a given hydrocarbon composition under various conditions of temperature and pressure. Simulator programs set up a computer model of an oil reservoir and can be used to predict displacement of fluid and composition changes within the reservoir during the course of oil recovery.
It is not unusual to make adjustments to a computer simulation or a predictive program, for example by adjusting the equation of state which is used, so as to arrive at a better fit to observed data. The hope is that such adjustments will give improvements in future predictions for the individual reservoir concerned, although the changes made may be empirical rather than evidence-based.